Overview or CO2 Injection Performance Metrics and the ... · •vertically-oriented reservoir cores...

Dr. David S. Schechter Texas A&M University

Overview or CO2 Injection –

Performance Metrics and the

Wellman Unit Case History

Utilization = Mcf CO2 per 1 Bbl EOR Recovery Factor vs. HCPV Injected

Important Metrics

CO2 EOR Primer NETL

Rule of Thumb? – Good Waterflood Good EOR Response

1

10

100

1000

10000

Jan

-46

Oct

-47

Jul-

49

Ap

r-5

1

Jan

-53

Oct

-54

Jul-

56

Ap

r-5

8

Jan

-60

Oct

-61

Jul-

63

Ap

r-6

5

Jan

-67

Oct

-68

Jul-

70

Ap

r-7

2

Jan

-74

Oct

-75

Jul-

77

Ap

r-7

9

Jan

-81

Oct

-82

Jul-

84

Ap

r-8

6

Jan

-88

Oct

-89

Jul-

91

Ap

r-9

3

Jan

-95

Oct

-96

Jul-

98

Ap

r-0

0

Jan

-02

Oct

-03

Jul-

05

Ap

r-0

7

Jan

-09

Oct

-10

Jul-

12

CO2-10C_Spot: Primary Oil Forecast

Oil Prod (BO/d) Water Prod (BW/d) Inj Wat (BWI/d)

CO2 Inj (Mcf/d) Primary Oil Forecast (BO/d)

0%

5%

10%

15%

20%

25%

0% 50% 100% 150% 200% 250% 300% 350% 400% 450%

Cu

m D

im D

EO

R (

%H

CP

V)

Cum Dim Injection (%HCPV)

CO2-10C_Spot: Dim Analysis Plots

DWI vs. DEOR_WF DCI vs. DEOR_CO2 DTI vs. DEOR_CO2

Primary decline

Waterflood decline

Gas injection decline

CO2-229_Spot

1

10

100

1000

10000

Jan

-46

Oct

-47

Jul-

49

Ap

r-5

1

Jan

-53

Oct

-54

Jul-

56

Ap

r-5

8

Jan

-60

Oct

-61

Jul-

63

Ap

r-6

5

Jan

-67

Oct

-68

Jul-

70

Ap

r-7

2

Jan

-74

Oct

-75

Jul-

77

Ap

r-7

9

Jan

-81

Oct

-82

Jul-

84

Ap

r-8

6

Jan

-88

Oct

-89

Jul-

91

Ap

r-9

3

Jan

-95

Oct

-96

Jul-

98

Ap

r-0

0

Jan

-02

Oct

-03

Jul-

05

Ap

r-0

7

Jan

-09

Oct

-10

Jul-

12

CO2-229_Spot: Primary Oil Forecast

Oil Prod (BO/d) Water Prod (BW/d) Inj Wat (BWI/d)

CO2 Inj (Mcf/d) Primary Oil Forecast (BO/d)

0%

5%

10%

15%

20%

25%

0% 50% 100% 150% 200% 250% 300% 350% 400%

Cu

m D

im D

EO

R (

%H

CP

V)

Cum Dim Injection (%HCPV)

CO2-229_Spot: Dim Analysis Plots

DWI vs. DEOR_WF DCI vs. DEOR_CO2 DTI vs. DEOR_CO2

feet F % md feet API cp %HCPV %OOIP MCF/STB MCF/STB -

Field Scale Projects

Dollarhide TX Trip. Chert 7,800 120 17.0 9 48 40 0.4 30 14.0 2.4 1985

East Vacuum NM Ooliti dolomite 4,400 101 11.7 11 71 38 1.0 30 8.0 11.1 6.3 1985

Ford Geraldine TX Sandstone 2,680 83 23.0 64 23 40 1.4 30 17.0 9.0 5.0 1981

Means TX Dolomite 4,400 100 9.0 20 54 29 6.0 55 7.1 15.2 11.0 1983

North Cross TX Trip. Chert 5,400 106 22.0 5 60 44 0.4 40 22.0 18.0 7.8 1972

Northeast Purdy OK Sandstone 8,200 148 13.0 44 40 35 1.5 30 7.5 6.5 4.6 1982

Rangely CO Sandstone 6,500 160 15.0 5 to 50 110 32 1.6 30 7.5 9.2 5.0 1986

SACROC (17 pattern) TX Carbonate 6,400 130 9.4 3 139 41 0.4 30 7.5 9.7 6.5 1972

SACROC (14 pattern) TX Carbonate 6,400 130 9.4 3 139 41 0.4 30 9.8 9.5 3.2 1981

South Welch TX Dolomite 4,850 92 12.8 13.9 132 34 2.3 25 7.6

Twofreds TX Sandstone 4,820 104 20.3 33.4 18 36 1.4 40 15.6 15.6 8.0 1974

Wertz WY Sandstone 6,200 165 10.7 16 185 35 1.3 60 10.0 13.0 10.0 1986

Producing Pilots

Garber OK Sandstone 1,950 95 17.0 57 21 47 2.1 35 14.0 6.0 1981

Little Creek MS Sandstone 10,400 248 23.4 75 30 39 0.4 160 21.0 27.0 12.6 1975

Majamar NM Anhydritic dolomite 4,050 90 10.0 11.2 49 36 0.8 30 8.2 11.6 10.7 1983

Majamar NM Dolomitic sandstone 3,700 90 11.0 13.9 23 36 0.8 30 17.7 8.1 6.1 1983

North Coles Levee CA Sandstone 9,200 235 15.0 9 136 36 0.5 63 15.0 7.4 1981

Quarantine Bay LA Sandstone 8,180 183 26.4 230 15 32 0.9 19 20.0 2.4 1981

Slaughter Estate TX Dolomitic sandstone 4985 105 12.0 8 75 32 2.0 26 20.0 16.7 3.7 1976

Weeks Island LA Sandstone 13,000 225 26.0 1200 186 33 0.3 24 8.7 7.9 3.3 1978

West Sussex WY Sandstone 3,000 104 19.5 28.5 22 39 1.4 30 12.9 8.9 1982

Field Projects ==> 11.7 6.3 Average

10.4 6.3 Median

Pilot Projects ==> 12.6 6.4 Average

8.9 6.0 Median

Metrics of Several Floods

Mode

Mode-2%OOIP

Mode+2%OOIP

The Permian Basin CO2

EOR Infrastructure Wellman

Unit

Wellman Unit Phase 1 Laboratory Evaluation of Injection

in the Transition Zone

Case History Wellman Unit

OUTLINE

• Introduction

• Laboratory Evaluation

• Field Performance

CO2 Recovery Mechanism

(Gravity Drainage)

• To examine the performance of recovery at or near the MMP with CO2 in:

• standard slim tube

• vertically-oriented, bead-packed large diameter tubes

• vertically-oriented reservoir cores at reservoir conditions

• To examine possibility that residual oil exists below the original water-oil contact that could be mobilized by continuation of CO2 injection

Wellman Unit Oil Characteristics

• separator oil taken at 61 oF and 126 psig

• average molecular weight: 147 g/mol

• GOR: 150 scf/bbl

• density: 0.8329 g/cm3 @ 100 oF and 1000 psig

• viscosity: 2.956 cp

Recovery vs. Pressure for Different GOR’s in

Slim Tube

60

70

80

90

100

1300 1400 1500 1600 1700 1800 1900

Pressure, psig

Ultim

ate

R

ec

ove

ry,

%O

OIP

GOR=150

GOR=400

GOR=600

MMP=1600~1625 psig

Recovery Curves for Each Large Diameter

Tube Test

0

20

40

60

80

100

120

0 20 40 60 80 100 120 140 160 180

% OOIP of CO2 Injected

% O

OIP

P

ro

du

ce

d O

il Run A: 1700 psig / gravity stable

Run B: 1550 psig / gravity stable

Run C: 1400 psig / gravity stable

Run D: 1700 psig / gravity stable

Run E: 1400 psig / gravity unstable

Run F: 1400 psig / horizontal

Cores From Wellman 5-10

• 30’ whole core from 9400’ to 9430’

• 26 samples for standard core analysis

• 3’ section for gravity stable CO2 tests

• helium porosities: 2.4% ~ 12.6%

• average porosity: 5.8% for 26 samples

• average water saturation: 42%

A Schematic Diagram of the Core Holder

and Procedure

CO2 @ 1650 psig

BPR

Oil

3500 psig

Confining

(4) (3) (2) (1)

Tem

per

atu

re =

15

0 o

F

Oil @ 1650 psig

Brine @ 2000 psig Brine @ 1650 psig

Vu

gu

lar C

arb

on

ate C

ore

Brine

BPR

BPR BPR

Fluid Production vs. CO2 Throughput During CO

2-

Assisted Gravity Drainage at a Pressure of 1650

psig

0

40

80

120

160

0 500 1000 1500 2000 2500 3000

CO2 Volume Injected, cc

Fluid V

olum

e

Produced, cc

Water Production, cc

Oil Production, cc

Oil Production x 1.33 ,

cc

After 9 days shut-in at

1640 psig and 150 F.After 3 days shut-in at

1740 psig and 150 F.

Changes in Fluid Saturations in the

Wellman Unit Whole Core During CO2-

Assisted Gravity Drainage

0

0.2

0.4

0.6

0 1 2 3 4 5 6 7

CO2 Volume Injected, PV

Sa

tu

ra

tio

ns, P

V

So (live)

SwAfter 3 days

shut-in at 1740

psig and 156 F

After 9 days shut-

in at 1640 psig

and 150 F

Oil Recovery From the Wellman Unit Whole

Core During CO2-Assisted Gravity Drainage

0

0.3

0.6

0.9

0 1 2 3 4 5 6 7

CO2 Volume Injected (PV)

Oil R

ecovery (O

OIP

)

After 3 days shut-

in at 1740 psig

and 156 F

After 9 days

shut-in at 1640

psig and 150 F

Oil Recovery From the Wellman Unit Whole Core

During CO2-Assisted Gravity Drainage at a Pressure

of 1650 psig

1300 1400 1500 1600 1700 1800 1900

Pressure, psig

0

10

20

30

40

50

60

70

80

90

100

Oil R

ecovery, %

OO

IP

Slim Tube - 1.2 PV

Large Diameter

Tube - 1.2 OOIP

Whole Core - 1.2 PV

Whole Core - 2 PV

Whole Core - 7 PV

1300 1400 1500 1600 1700 1800 1900

Pressure, psig

0

10

20

30

40

50

60

70

80

90

100

Oil R

ecovery, %

OO

IP

0

10

20

30

40

50

60

70

80

90

100

Oil R

ecovery, %

OO

IP

Slim Tube - 1.2 PV

Large Diameter

Tube - 1.2 OOIP

Whole Core - 1.2 PV

Whole Core - 2 PV

Whole Core - 7 PV

Sor

From the Wellman Unit Whole Core

During CO2-assisted Gravity Drainage at

Three Pressures Above and Below the MMP

0

10

20

30

40

1400 1500 1600 1700 1800

Pressure, Psig

So

r, %

Slim Tube Test, GOR=150

Large Diameter Tube

Whole Core

Gravity Stable Outperforms Slim Tube!

Core-flooding Experiments

SPE-190183-MS

2018 SPE IOR

The Impact of Gas-Assisted Gravity Drainage on

Operating Pressure in a Miscible CO2 Flood

Wellman Unit Phase 2 Reservoir Performance of Injection in the

Transition Zone

Case History Wellman Unit

Wellman

Field

Midland

Horseshoe Atoll

LOCATION

Terry county, TX, along the Horseshoe Atoll reef complex that developed in North Midland during Pennsylvanian and early Permian time

INTRODUCTION

• History of the Wellman Unit CO2 flood

• Two possibilities to optimize reservoir performance ―Reducing CO2 injection pressure to near the MMP

―Mobilizing reserves in the water-oil transition zone below the original water-oil contact

Wellman Unit Structure Map

Amount of CO2 Sequestered in Gas Cap– 130 Bcf

2,100 acres = 3.3 mi2 = 8.5 km2

Primary Depletion (1950 – 1979)

1) 1950-53 oil rate peaked 6 MSTBD

2) 1954 allowable restrictions oil rate

reduced to 3, then 1.7 MSTBD

3) 1966 oil rate peaked 8 MSTBD

4) 1976-79 produced below Pb until

reached minimum 1,050 psig

Pb at 1,248 PSI

1

2

3

4

Cum. Oil: 41.8 MMSTB

RF: 34.6%

Historical Reservoir Performance

5) 1976-79 GOR did not increase

secondary gas cap formed.

H2O cut: from 10 to 25%

5

Primary Depletion (1950 – 1979)



RF: 34.6%

Waterflooding (1979 – 1983)


Sec. RF: 19.5%

H2O Inj

CO2 Inj

OWOC

H2O Inj

CO2 Inj

OWOC

H2O Inj

OWOC

1979 - four flank H2O injectors

re-pressurize (MMP), re-dissolve

part of the gas, displace oil

upward


Waterflooding

• Pressure increased from

1,050 to1,600 psig prior CO2

(1983)

• Water cut from 25 to 40%

GOR aprox. constant

• Water cut controlled by plug

downs

• Oil rate increased to 9

MSTBD


Waterflooding (1979 – 1983)

H2O Inj

CO2 Inj

OWOC

H2O Inj

CO2 Inj

OWOC

H2O Inj

CO2 Inj

OWOC

• 1983-89 - Three crestal

Injectors to displace oil

downward and reduce

Sor

CO2 Injection (1983 – 1995)


Cum. Oil: 6.3 MMSTB

Ter. RF: 5.4%

• 1984-89, CO2 Inj. From 5 to 15

MMCFD.

• 1985, break water cut from 40 to

85%. (ESP’s, leaks, corrosion)

• GOR peaked to 3000 SCF/STB

(mostly CO2)

• Pressure from 1600 to 2,300

peaked at 2,500 psig in 1994.

Primary

Depletion CO2

Injection

Waterflooding


Cum. Oil: 6.3 MMSTB

Ter. RF: 5.4%

CO2 Injection (1983 – 1995)

Wellman Unit Annual CO2 Utilization

Wellman Unit Individual Static Bottom Hole

Pressure

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

A-49 M-53 J-57 A-61 S-65 O-69 D-73 J-78 F-82 M-86 M-90 J-94

Time, years

Bo

tto

m H

ole

Pre

ssu

re (B

HP

), P

si

Unit 1-1 Unit 2-1 Unit 2-3 Unit 3-3 Unit 4-1 Unit 4-2

Unit 4-3 Unit 4-4 Unit 4-5 Un it 4-6 Unit 4-7 Unit 5-1


Unit 7-1 Unit 7-2 Unit 8-3 Unit 8-5 Unit 8-6 Unit 8-7A

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

A-49 M-53 J-57 A-61 S-65 O-69 D-73 J-78 F-82 M-86 M-90 J-94

Time, years

Bo

tto

m H

ole

Pre

ssu

re (B

HP

), P

si



Unit 5-2 Unit 5-3 Unit 5-4

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

A-49 M-53 J-57 A-61 S-65 O-69 D-73 J-78 F-82 M-86 M-90 J-94

Time, years

Bo

tto

m H

ole

Pre

ssu

re (B

HP

), P

si




Unit 7-1 Unit 7-2 Unit 8-3 Unit 8-5 Unit 8-6 Unit 8-7A

Chronological Stages of Depletion

Bottom Water Drive

Original Reservoir Conditions

Sec. Gas

Cap

Prod Prod

Bottom Water Drive

Before Waterflooding (1979)

Prod Prod

WIW WIW

Bottom Water Drive

Waterflooding (Before CO 2 Flood),1983

CO2 ICO2 I

WIWWIW

Prod Prod

Waterflood and CO2 Injection (1995)

Bottom Water Drive

Bottom Water Drive


Bottom Water Drive


Sec. Gas

Cap

Prod Prod

Bottom Water Drive


Prod Prod

WIW WIW

Bottom Water Drive


CO2 ICO2 I

WIWWIW

Prod Prod


Bottom Water Drive

CO2 ICO2 I

WIWWIW

Prod Prod


Bottom Water Drive

WIWWIW

Prod Prod


Bottom Water Drive

Bottom Water Drive


Bottom Water Drive


Sec. Gas

Cap

Prod Prod

Bottom Water Drive


Prod Prod

WIW WIW

Bottom Water Drive


CO2 ICO2 I

WIWWIW

Prod Prod


Bottom Water Drive

CO2 ICO2 I

WIWWIW

Prod Prod


Bottom Water Drive

WIWWIW

Prod Prod


Bottom Water Drive

Bottom Water Drive


Bottom Water Drive


Sec. Gas

Cap

Prod Prod

Bottom Water Drive


Prod Prod

WIW WIW

Bottom Water Drive


CO2 ICO2 I

WIWWIW

Prod Prod


Bottom Water Drive

WIWWIW

Prod Prod


Bottom Water Drive

CO2 ICO2 I

WIWWIW

Prod Prod


Bottom Water Drive

WIWWIW

Prod Prod


Bottom Water Drive

INITIAL WATER DISTRIBUTION PROFILE SHOWING WOC,

TRANSITION ZONE AND IRREDUCIBLE WATER

SATURATION (20%) IN THE OIL ZONE

Simulation Model 3D – Structure Development

Gross Thickness Porosity Net to Gross Ratio

Simulation Model Input Data

Permeability

• Use previous estimations from correlations between open logs and core

measurements K = 10^(0.167 * Core porosity – 0.537)

• Relationship may not be representative due to fractures and vugular porosity

Water Saturation

Swc, aprox 20% for Ф = 8.5%Swc, aprox 20% for Ф = 8.5%


Fluid Properties

• Use PVT properties contained in previous lab and reservoir studies

• Bubble point: 1248 – 1300 psig

• Rs, 400-500 SCF/STB

• Oil Gravity, 43 API

• OFVF, 1.30 RB/STB

• Oil Viscosity, 0.4 cp

• Black oil fluid type

Relative Permeability

• Special core analysis for core well No. 7-6 included measurements on only

two samples with a low non-representative permeability

• Use functions derived from Honarpour’s correlation (past studies)


Initial Oil - Water Relative Permeability

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Water saturation (Sw),fraction

Rela

tive P

erm

eab

ilit

y, fr

acti

on

Krow

Krw

Initial Gas - Oil Relative Permeability

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8

Gas saturation (Sg) fraction

Rela

tive P

erm

eab

ilit

y, fr

acti

on Krg

Krog

Initial Oil-water and gas Relative Permeability


Capillary Pressure Data

• Only 4 samples , K> 1 md

(Special core Analysis) Leverett's- J Function Vs. Water Saturation

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 10 20 30 40 50 60 70 80 90 100

Water saturation (Sw), percentage

J-

Fu

ncti

on

CC-76 H, K=18 md CC-77 H,K=161 md

CC-79 H,K= 9.07 md CC-86 H,K= 18 md

• Shape suggests lack of

capillary transition zone

• Data normalized by

Leverett’s J-function

• Good vertical communication

capillary effect “no significant”


Results: Primary Depletion Diagnosis

Results: Waterflooding WOC Movement

(a)

(b)

(c)

1950

1979

1983

208 ft

210 ft

a)

b)

c)

1979

1983

1995

Results: CO2 Injection Chronological Oil Saturation Distribution

a) Primary depletion

b) Waterflooding

c) CO2 miscible flooding

Oil saturation considered

overestimated due to the

excess of oil production

Recycle Compressor

NGL Recovery Plant

Tank Battery

Production Separators

Conclusions

• CO2 flooding in the W.U. has performed exceptionally well due to

gravity stable displacement above MMP.

• Reducing pressure from above the MMP to near the MMP does not

reduce efficiency in laboratory. BHP in the W.U. could be reduced to

near the MMP with no reduction in displacement efficiency.

• The reduction in CO2 purchases would be a positive benefit. The

reduction in reservoir pressure is constrained by voidage replacement

issues.

• Excellent sweep and displacement efficiency is observed in the lab and

the field with residual oil saturation in strong agreement with lab and

gas cap.

• Over 130 Bcf of CO2 has been injected and sequestered in the gas cap.

• Gravity drainage combined with excellent well diagnostics and

monitoring results in outstanding recovery factor of 63%.

This is why I don’t like 4000 psi anymore …

DuPontTM Viton®

• 3,000 hr at 450 °F

• 48 hr at 601 °F

• Resistance to chemical degradation to oil, fuels, lubricants, and most mineral acids

• Resistance to aliphatic, aromatic hydrocarbons that dissolve other rubbers.

• Resistance to atmospheric oxidation, sun, and weather. Fungus and mold

However…after 35 hr with CO2 at 4000 psi and 165 ° F

WARNING: GRAPHIC CONTENT

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Team Effort

Introduction

Core-flooding + CT scanning integrated equipment

Reservoir temperature

Reservoir pressure

Confining pressure

CT Scanning capability

URTEC 2903026 | Gas Injection for EOR in Organic Rich Shales. Part II

Introduction

Core-flooding + CT scanning integrated equipment


Introduction

CO2 Injection in shale physical simulation

CO2 is injected

CO2 is displaced with fresh

CO2

Soaking is allowed (0 – 22 hr)

CT Scanning is done periodically

The pressure is kept constant


Produced oil


0

5

10

15

20

25Crude oil 1

Crude oil 1 + dopant

run 1.1

run 1.4

2.

2. – Effluents was flashed at room conditions

3. – The produced oil is clearly lighter than the injected oil

4. – The oil produced from the Berea is heavier than the oil

produced from the organic rich shale

1. – Dead oil

1.

Slice from the edge

1 in

(2.54 cm)

0.57 hr 25.25 hr 50.78 hr 73.63 hr 103.90hr

Test run 2.4

2nd set – well 2

3100 psig | 21 hrs

RF = 26.15 %

Slice from the center


Compositional changes with time

CO2

SPE-191752-MS

The Impact of MMP on Recovery Factor During

CO2 – EOR in Unconventional Liquid Reservoirs

Imad A. Adel, Francisco D. Tovar, Fan Zhang, David S. Schechter,

Texas A&M University

Results and Discussions

Minimum Miscibility Pressure

Slide 68

• The addition of iodobenzene does not cause

a significant increase in the oil density either

SPE-191752-MS • The Impact of MMP on Recovery Factor During CO2 – EOR in Unconventional Liquid Reservoirs • Imad Adel


Effect of pressure on recovery factor

Slide 69

Increasing pressure always leads to an increase in the recovery

factor



Time-frame for recovery

Slide 70

• Most of the oil is recovered during the first cycle

• Similar results were observed in all the huff-and-puff experiments

• The oil recovery rate starts decreasing after the first cycle until it levels off as the maximum recovery

is approached

Recovery factor per cycle during CO2 huff-and-puff experiment on core plug EF3 at 3,500 psig and soak time of 10 hours



CT-Scanning

Slide 71

• CT-scans are performed regularly to track the

changes in density as a function of time and

space.

• The color on the left side changed from blue

and green color to red, which means the density

of that area decreased to a lower value

Evidence that CO2 penetrate into the

core plug and oil extracted out from the

matrix

CT-scan images from the gas injection experiment of core EF3 at 3,500 psi



CT-Scanning

Slide 72

• The CT number of the doped oil is higher than the CT number

of the CO2 phase at all pressures:

This CT number decrease indicates that the oil was

replaced by the CO2 inside of the core

• The CT number of the doped oil is higher than the CT number

of the CO2 phase at all pressures

Average CT number for entire core plug during gas injection experiment

at 3,500 psi



CT-Scanning

Slide 73

• The slices at both end of the core plug, have a

more substantial CT number decreases during

the experiment.

• The CT value of slices1 and 37 is lower than

slices at the middle of the core:

Average CT number for each slice during gas injection experiment at 3,500 psi

CO2 contacts a larger area per slice at the

edges of the cores, Hence a larger decrease

in CT values.



CT-Scanning – Flow path

Slide 74

High flow path region from the experiment at 3,500 psi for slices 4 and corresponding CT image

before the experiment


The pixels for delta CT number above 50 HU

were marked as 1

We counted the number of times high

CT number were shown for each pixel

during the gas injection experiment

The high flow path region can be

generated and used to deterermine

the parameters of the core-scale

simulation model

1 .9 .8 .7 .6 .5 .4 .3 .2 .1 0

.9

.8

.7

.6

.5

.4

.3

.2

.1

0

1 0

.1

.2

.3

.4

.5

.6

.7

.8

.9

1

Injection gas

Intermediate Heavy ends

Vaporizing gas drive

Gas

Liquid

Mixture

Critical point

Critical tie line Slim tube MMP is developed

after multiple contacts


1 .9 .8 .7 .6 .5 .4 .3 .2 .1 0

.9

.8

.7

.6

.5

.4

.3

.2

.1

0

1 0

.1

.2

.3

.4

.5

.6

.7

.8

.9

1

Injection gas


Peripheral slow-kinetics vaporizing gas drive

Gas

Liquid

Mixture

Critical point

Critical tie line

Production

Production

Huff-and-puff

Poor transport slows down the

development of miscibility

We disrupt the process with each

production cycle




Carbon dioxide

Oil

Miscible front

Legend

1 .9 .8 .7 .6 .5 .4 .3 .2 .1 0

.9

.8

.7

.6

.5

.4

.3

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0

1 0

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1

Injection gas


Gas

Liquid

Mixture

Critical point

Critical tie line

Continuous flooding

Production

We are continuously disrupting the

gas enrichment process



1 .9 .8 .7 .6 .5 .4 .3 .2 .1 0

.9

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Injection gas


Gas

Liquid

Mixture

Critical point

Critical tie line

Pressure effect

Increasing the pressure improves

the ability of the gas to strip out oil

components



Minimum Miscibility Pressure (MMP) for Eagle Ford Oil

• The MMP was measured using the slim tube technique using an 80-ft coil

• The MMP was determined to be 2,132 psi.

Slide 80

SPE-191502-MS • Enhanced Oil Recovery in Unconventional Liquid Reservoir Using a Combination of CO2 Huff-n-Puff and

Surfactant-Assisted Spontaneous Imbibition • Fan Zhang

Results of Gas Injection Experiments

• The recovery factors

increases as the

pressure increases.

• The maximum RF is

49% of OOIP at

3,500 psi.

• RF is less than 5%

when pressure below

MMP.

Slide 81



Results of SASI Related Experiments

• Surfactants lead to wettability alteration and IFT reduction.

• Up to an extra 12% of oil recovered through spontaneous imbibition

experiments

Slide 82



0%

2%

4%

6%

8%

10%

12%

14%

Core 1 Core 2 Core 3 Core 4

Re

co

ve

ry F

ac

tor (

%)

Observation during SASI

• At the beginning of SASI, foam was

collected at the top cylinder.

• CO2 existed inside the core plugs after gas

injection experiments.

• Even though 49% of OOIP produced from

gas injection experiment, additional oil can

be recovered from SASI.

Slide 83



Recovery Factor of Hybrid EOR Experiments

• Up to 49% of OOIP was produced from CO2 huff-n-puff experiments.

• The maximum recovery factor of hybrid EOR experiments is 58% of

OOIP.

Slide 84



0%

10%

20%

30%

40%

50%

60%

70%

Core 1 Core 2 Core 3 Core 4

Re

co

ve

ry

Fa

cto

r (

%)

RF- SASI RF- CO2

Experimental Timeline

• Three months of re-saturation and aging process.

• Recovering up to 58% of the OOIP in only 12 days.

Slide 85



CT-Scan Images from Gas Injection and Imbibition Experiments

• Gas injection experiments: more oil recovered from low CT number

region (larger pores).

• SASI: most of oil produced from high CT number region (smaller

pores).

Slide 86



Color Change of Produced Oil

• Lighter and intermediate components of the oil are recovered during

the CO2 huff-n-puff experiments.

• Heavier components are recovered during the SASI.

Slide 87



Color Change of Oil during Spontaneous Imbibition Experiments

• The color of the

produced oil changed

from lighter to darker.

• Lighter components of

oil are recovered within

the first 24 h.

• A large fraction of the oil

produced from the SASI

is coming from the

smaller pores.

Slide 88



Low IFT Imbibition and Drainage

Dr. David S. Schechter Texas A&M University

Low IFT Imbibition and Drainage:

Gravity Dominates at Low IFT

Imbibition: Mechanisms and Recovery

Imbibition

Mechanisms

Imbibition

Recovery

Capillary Imbibition Cell

Imbibition Rate Theory

Correlation of IFT and Dr

Capillary and Gravity Imbibition

Phase Diagram for Brine/IC8/IPA System

Phase Behavior Data

Imbibition in 15 md Limestone

Imbibition in 100 md Berea

Imbibition in 500 md Berea

Imbibition in 700 md Brown Sandstone

Bond Number

Remaining Saturation vs. CGR for Imbibition

Remaining Oil Saturations at Different IFTs

Critical Scaling Theory

Test of Critical Scaling

Critical Scaling

Drainage: Mechanisms and Recovery

Drainage

Mechanisms

Drainage

Recovery

Gravity Drainage Cell

Remaining Saturation vs. CGR for Drainage

Height vs. Permeability for NB

-1 = 1 for the CO2/C10 System

Non-equilibrium Drainage

Non-equilibrium Drainage: Vaporizing Case

Imbibition and Drainage in 500 md Berea

Spontaneous Imbibition and Drainage

Conclusions

Imbibition at high value of NB-1 (NB

-1 > 5) is dominated by capillary forces, and the rate of imbibition is limited by the counter-current flow of the wetting and nonwetting phase.

At low values of NB-1 (NB

-1 << 1), imbibition is dominated by vertical flow driven by gravity forces.

Conclusions

For intermediate values of NB-1, the

combined effects of gravity segregation and capillary-driver imbibition can lead to faster recovery of the nonwetting phase than is observed for either gravity-dominated of capillary-dominated flow.

Gravity drainage of wetting phase from fully saturated vertical cores occurs for NB

-1 < 1.

Conclusions

Gas injection processes can be used to recover oil from fractured reservoirs by gravity drainage at low NB

-1.

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Recovery factors under nitrogen injection

N2

Overview or CO2 Injection Performance Metrics and the ... · •vertically-oriented reservoir cores...

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